EP0570228B1 - Recovery of fuel gases from underground deposits - Google Patents
Recovery of fuel gases from underground deposits Download PDFInfo
- Publication number
- EP0570228B1 EP0570228B1 EP93303723A EP93303723A EP0570228B1 EP 0570228 B1 EP0570228 B1 EP 0570228B1 EP 93303723 A EP93303723 A EP 93303723A EP 93303723 A EP93303723 A EP 93303723A EP 0570228 B1 EP0570228 B1 EP 0570228B1
- Authority
- EP
- European Patent Office
- Prior art keywords
- deposit
- gas
- stream
- coal
- process according
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
Links
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/006—Production of coal-bed methane
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
Definitions
- This invention relates to the production of gases from underground mineral formations, and more particularly to the enhanced production of natural gas or the components of natural gas from an underground coal formation using a strongly adsorbable fluid and a weakly adsorbable gas in combination to stimulate release of the desired gases.
- coal formations and other such carbon deposits contain natural gas components, such as the lower molecular weight hydrocarbons, due to effects of long term coalification.
- Coal generally has a low porosity, hence most of the coalbed gas is in the form of sorbate on the surfaces of the coal rather than being entrapped within the coal.
- the gas is present in the coal deposit in significant quantities; accordingly it is economically desirable to extract it for use as fuel and for other industrial purposes.
- Coalbed gas is conventionally produced from underground coal deposits by pressure depletion.
- a well is drilled into the coal deposit and a suction is applied to the well to withdraw the gas from the deposit.
- a process for recovering an adsorbed fuel gas from an underground deposit comprising injecting a first stream comprising one or more strongly adsorbable fluids into said deposit; injecting a second stream comprising one or more weakly adsorbable gases into said deposit, thereby causing said strongly absorbable fluids to flow through said deposit and desorb said fuel gas therefrom; and withdrawing said fuel gas from the deposit.
- gaseous substances such as natural gas components
- subterranean solid carbonaceous formations such as coal deposits, or which are otherwise trapped in the formation
- gaseous substances are released from the formation and forced to the surface of the earth by injecting a strongly adsorbable fluid stream comprising one or more strongly adsorbable fluids into the formation and then injecting a gas stream comprising one or more weakly adsorbable gases into the formation in a manner such that the weakly adsorbable gas stream forces the strongly adsorbable fluid(s) to move through pores, cracks and seams in the formation toward a gas collection point in or at the end of the formation.
- the fluid stream comprising the one or more strongly adsorbable components When the fluid stream comprising the one or more strongly adsorbable components is injected into the deposit it facilitates release of the gaseous substances adsorbed or trapped therein.
- the gas stream comprising the one or more weakly adsorbable gases When the gas stream comprising the one or more weakly adsorbable gases is injected into the deposit it forces the strongly adsorbable fluid stream to move through the formation ahead of the weakly adsorbable gas stream.
- the strongly adsorbable fluid stream is in the form of a liquid, as it moves through the formation, which is often at a temperature of about 35 to 60° C. or more, all or a portion of liquid fluid likely vaporises. When this occurs, the vapour moves through the formation, and as it does so it desorbs the gaseous substances therefrom and sweeps them toward the gas collection point. At the collection point the desorbed gaseous substances, which may be mixed with the vapours, are withdrawn from the
- the gaseous substances recovered by the process of the invention are the gases that are normally found in underground solid carbonaceous formations such as coal deposits. These include the components of natural gas, which is made up mostly of lower molecular weight hydrocarbons, i.e. hydrocarbons having from 1 to about 6 carbon atoms. The most prevalent hydrocarbons in such natural gas are those having up to 3 carbon atoms, and by far the most highly concentrated hydrocarbon present is methane. Other gases, such as nitrogen, may also be present in the formation in small concentrations.
- the strongly adsorbable fluid used in the process of the invention may be any gas, liquefied gas or volatile liquid that is non-reactive and which is more strongly adsorbed by the carbonaceous matter in the formation than are the gaseous substances that are to be recovered from the formation.
- non-reactive is meant that the fluid does not chemically react with the carbonaceous matter or the gaseous substances present in the formation at the temperatures and pressures prevailing in the formation. It is preferred to use liquefied gases or volatile liquids that rapidly evaporate at the conditions existing in the underground formation.
- Liquefied carbon dioxide is preferred for use in the process of the invention because it is easily liquefied and is more strongly adsorbed onto the carbonaceous material than are the gaseous substances which it is desired to recover, hence it efficiently desorbs the gaseous substances from the coal as it passes through the bed.
- Carbon dioxide has the additional advantages that it evaporates at the temperatures and pressures usually prevailing in the formation, thereby forming the more efficiently adsorbed gas phase, and it is easily separated from the recovered gaseous substances because its boiling point is high relative to the boiling points of the recovered gaseous substances. Because of the latter advantage, it can be separated from the recovered formation gases by cooling the gas mixture sufficiently to condense the carbon dioxide.
- the liquefied carbon dioxide recovered by condensation can be reused in the process of the invention.
- the strongly adsorbable fluid stream may comprise a single strongly adsorbable component, or it may comprise a mixture of two or more strongly adsorbable components.
- the presence of minor amounts of weakly adsorbable gases in the strongly adsorbable fluid stream will not prevent the strongly adsorbable fluid from performing its intended function in the process of the invention.
- the strongly adsorbable component(s) are present as the major components of this stream.
- the strongly adsorbable component(s) comprise at least 75 and most preferably at least 90 volume percent of the strongly adsorbable fluid stream.
- Typical strongly adsorbable component streams comprise substantially pure carbon dioxide or mixtures of carbon dioxide as the major component and an weakly adsorbable gas, such as nitrogen, argon or oxygen, as a minor component.
- the weakly adsorbable gas used in the process of the invention can be any gas or mixture of gases that is nonreactive, i.e. it does not chemically react with the carbonaceous material or the gaseous substances contained in the formation at the temperatures and pressures prevailing in the formation.
- Preferred weakly adsorbable gases are those that are not readily adsorbed onto the surfaces of the carbonaceous material.
- Typical gases that can be used as the weakly adsorbable gas in the process of the invention are nitrogen, argon, helium, air, nitrogen-enriched air and mixtures of two or more of these. Nitrogen and nitrogen-enriched air are the most preferred weakly adsorbable gases because they are less expensive and more readily available than argon and helium and safer to use than air.
- the weakly adsorbable gas stream may contain minor amounts of strongly adsorbable gases, such as carbon dioxide.
- strongly adsorbable gases perform no useful function in the weakly adsorbable gas stream it is preferred that the concentration of these gases in this stream be kept to a minimum.
- the process of the invention can be used to produce gases from any solid underground carbonaceous formation.
- typical carbonaceous deposits from which valuable fuel gases can be produced are anthracite, bituminous and brown coal, lignite, peat.
- injection wells can be positioned at the corners of a rectangular section above the formation and a production well can be positioned in the centre of the rectangle.
- the gas production field can consist of a central injection well and several production wells arranged around the injection well or a line-drive pattern, i.e.
- Fig. 1 is a side elevation of a subterranean formation containing a solid carbonaceous deposit, wherein the deposit is penetrated by an injection well and a production well.
- Fig. 2 is a side elevation of the formation of Fig. 1, after liquefied gas has been injected into the deposit illustrated therein;
- Fig. 3 is a side elevation of the formation shown in Fig. 1 after liquefied gas and weakly adsorbable gas have been injected into the deposit illustrated therein.
- a coal deposit 2 which is penetrated by injection well 4 and gas production well 6.
- Line 8 carries the fluid to be injected into the coal deposit from a source (not shown) to pump 10, which raises the pressure of the fluid being injected into the coal deposit sufficiently to enable it to penetrate the deposit.
- the high pressure fluid is carried into well 4 via line 12.
- the fluid in well 4 passes through the wall of well 4 through openings 14.
- Methane is withdrawn from the coal deposit by pump 16.
- the methane enters well 6 through openings 18, rises to the surface through well 4 and enters pump 16 via line 20.
- the methane is discharged from pump 16 to storage or to a product purification unit (not shown) through line 22.
- Fig. 2 illustrates the first step of the process of the invention.
- liquefied carbon dioxide is pumped into coal deposit 2.
- the direction of movement of the liquefied carbon dioxide through well 4 is represented by arrow 24 and the direction of flow of the liquefied carbon dioxide into the coal deposit is represented by arrows 26.
- the liquefied carbon dioxide passing through the coal deposit forms a front, represented by reference numeral 28.
- reference numeral 28 As the liquefied carbon dioxide moves through the coal deposit it stimulates the release of methane from the deposit.
- the second step of the invention is illustrated in Fig. 3.
- nitrogen is pumped into the coal deposit after the desired amount of liquefied carbon dioxide is pumped into the deposit.
- the flow of nitrogen through well 4 is represented by arrow 32, and the flow of nitrogen into coal deposit 2 is represented by arrows 34.
- the body of liquefied carbon dioxide appears to act as a buffer between the methane and the nitrogen, thereby tending the inhibit mixing of the nitrogen with the methane being recovered from the deposit.
- Injection and production wells are drilled into a coal seam containing adsorbed methane in a repeating line-drive pattern having a well-to-well distance of 1000 ft.
- Liquefied carbon dioxide is then injected into the coal seam through the injection wells, until a total of 15,000 bbl. per well is injected into the seam.
- nitrogen is injected into the coal seam through the injection wells as a propellant gas. As the nitrogen is pumped into the wells, a methane-rich gas stream is removed from the seam through the production wells.
- Example I The procedure of Example I is repeated except that no nitrogen propellant gas is injected into the coal seam.
- the total volume of methane removed from the coal seam will be about 23.7 (10 6 ) scf per well.
- Example I The procedure of Example I is repeated except that no liquefied carbon dioxide is injected into the coal seam. At the point of nitrogen break-through, 3.0 (10 6 ) scf per well of nitrogen will have been injected into the coal seam and the volume of methane removed from the well will have reached about 15.9 (10 6 ) scf per well.
Description
- This invention relates to the production of gases from underground mineral formations, and more particularly to the enhanced production of natural gas or the components of natural gas from an underground coal formation using a strongly adsorbable fluid and a weakly adsorbable gas in combination to stimulate release of the desired gases.
- Underground coal formations and other such carbon deposits contain natural gas components, such as the lower molecular weight hydrocarbons, due to effects of long term coalification. Coal generally has a low porosity, hence most of the coalbed gas is in the form of sorbate on the surfaces of the coal rather than being entrapped within the coal. The gas is present in the coal deposit in significant quantities; accordingly it is economically desirable to extract it for use as fuel and for other industrial purposes.
- Coalbed gas is conventionally produced from underground coal deposits by pressure depletion. According to one technique for practicing this procedure, a well is drilled into the coal deposit and a suction is applied to the well to withdraw the gas from the deposit. Unfortunately water gradually enters the coal deposit as the pressure in the deposit decreases, and as the water accumulates in the deposit, it hinders withdrawal of gas from the deposit. The drop in pressure as the process proceeds, and complications caused by the influx of water into the deposit, lead to a rapid decrease in the gas production rate and eventual abandonment of the effort after a relatively low recovery of the coalbed gas.
- To avoid the difficulties of the above-described pressure depletion method, attempts to recover gases from a coal deposit by injecting gaseous carbon dioxide into the deposit have been made. The carbon dioxide is injected into the coal deposit through an injection well which penetrates the deposit. The advantage of this procedure is that the carbon dioxide displaces the desired gas from the surfaces of the coal and sweeps it toward a production well which has also been drilled into the deposit, but at a distance from the injection well. Although this method affords a greater recovery of the coalbed gas than the pressure depletion method, it is prohibitively costly because large volumes of carbon dioxide are required to effect a reasonable recovery of the gas from the deposit.
- It is also known to inject an inert gas, such as nitrogen or argon, into the coal deposit to force the coalbed gas from the coal deposit. This procedure is disclosed in U. S. Patent 4,883,122. The method of recovery has the disadvantage that the inert gas is not adsorbed onto the coal; hence it does not easily desorb the coalbed gases. Consequently, although the inert gas does sweep some coalbed gas from the deposit, the inert gas is removed from the deposit with the coalbed gas. The presence of the inert gas in the coalbed gas removed from the deposit reduces its value as a fuel.
- Because of the value of the coalbed gas, methods for the efficient recovery of coalbed gas from coal deposits which are free of the above-noted disadvantages of prior art recovery techniques are constantly sought. This invention provides such an improved method.
- According to the present invention there is provided a process for recovering an adsorbed fuel gas from an underground deposit comprising injecting a first stream comprising one or more strongly adsorbable fluids into said deposit; injecting a second stream comprising one or more weakly adsorbable gases into said deposit, thereby causing said strongly absorbable fluids to flow through said deposit and desorb said fuel gas therefrom; and withdrawing said fuel gas from the deposit.
- According to the invention, gaseous substances, such as natural gas components, that are adsorbed onto the surfaces of subterranean solid carbonaceous formations, such as coal deposits, or which are otherwise trapped in the formation, are released from the formation and forced to the surface of the earth by injecting a strongly adsorbable fluid stream comprising one or more strongly adsorbable fluids into the formation and then injecting a gas stream comprising one or more weakly adsorbable gases into the formation in a manner such that the weakly adsorbable gas stream forces the strongly adsorbable fluid(s) to move through pores, cracks and seams in the formation toward a gas collection point in or at the end of the formation. When the fluid stream comprising the one or more strongly adsorbable components is injected into the deposit it facilitates release of the gaseous substances adsorbed or trapped therein. When the gas stream comprising the one or more weakly adsorbable gases is injected into the deposit it forces the strongly adsorbable fluid stream to move through the formation ahead of the weakly adsorbable gas stream. If the strongly adsorbable fluid stream is in the form of a liquid, as it moves through the formation, which is often at a temperature of about 35 to 60° C. or more, all or a portion of liquid fluid likely vaporises. When this occurs, the vapour moves through the formation, and as it does so it desorbs the gaseous substances therefrom and sweeps them toward the gas collection point. At the collection point the desorbed gaseous substances, which may be mixed with the vapours, are withdrawn from the formation.
- The gaseous substances recovered by the process of the invention are the gases that are normally found in underground solid carbonaceous formations such as coal deposits. These include the components of natural gas, which is made up mostly of lower molecular weight hydrocarbons, i.e. hydrocarbons having from 1 to about 6 carbon atoms. The most prevalent hydrocarbons in such natural gas are those having up to 3 carbon atoms, and by far the most highly concentrated hydrocarbon present is methane. Other gases, such as nitrogen, may also be present in the formation in small concentrations.
- The strongly adsorbable fluid used in the process of the invention may be any gas, liquefied gas or volatile liquid that is non-reactive and which is more strongly adsorbed by the carbonaceous matter in the formation than are the gaseous substances that are to be recovered from the formation. By non-reactive is meant that the fluid does not chemically react with the carbonaceous matter or the gaseous substances present in the formation at the temperatures and pressures prevailing in the formation. It is preferred to use liquefied gases or volatile liquids that rapidly evaporate at the conditions existing in the underground formation. Liquefied carbon dioxide is preferred for use in the process of the invention because it is easily liquefied and is more strongly adsorbed onto the carbonaceous material than are the gaseous substances which it is desired to recover, hence it efficiently desorbs the gaseous substances from the coal as it passes through the bed. Carbon dioxide has the additional advantages that it evaporates at the temperatures and pressures usually prevailing in the formation, thereby forming the more efficiently adsorbed gas phase, and it is easily separated from the recovered gaseous substances because its boiling point is high relative to the boiling points of the recovered gaseous substances. Because of the latter advantage, it can be separated from the recovered formation gases by cooling the gas mixture sufficiently to condense the carbon dioxide. The liquefied carbon dioxide recovered by condensation can be reused in the process of the invention.
- As indicated above, the strongly adsorbable fluid stream may comprise a single strongly adsorbable component, or it may comprise a mixture of two or more strongly adsorbable components. The presence of minor amounts of weakly adsorbable gases in the strongly adsorbable fluid stream will not prevent the strongly adsorbable fluid from performing its intended function in the process of the invention. However, since the principal benefit is derived from the strongly adsorbable component(s), the strongly adsorbable component(s) are present as the major components of this stream. In general, it is preferred that the strongly adsorbable component(s) comprise at least 75 and most preferably at least 90 volume percent of the strongly adsorbable fluid stream. Typical strongly adsorbable component streams comprise substantially pure carbon dioxide or mixtures of carbon dioxide as the major component and an weakly adsorbable gas, such as nitrogen, argon or oxygen, as a minor component.
- The weakly adsorbable gas used in the process of the invention can be any gas or mixture of gases that is nonreactive, i.e. it does not chemically react with the carbonaceous material or the gaseous substances contained in the formation at the temperatures and pressures prevailing in the formation. Preferred weakly adsorbable gases are those that are not readily adsorbed onto the surfaces of the carbonaceous material. Typical gases that can be used as the weakly adsorbable gas in the process of the invention are nitrogen, argon, helium, air, nitrogen-enriched air and mixtures of two or more of these. Nitrogen and nitrogen-enriched air are the most preferred weakly adsorbable gases because they are less expensive and more readily available than argon and helium and safer to use than air. As was the case with the strongly adsorbable fluid stream, the weakly adsorbable gas stream may contain minor amounts of strongly adsorbable gases, such as carbon dioxide. However, since strongly adsorbable gases perform no useful function in the weakly adsorbable gas stream it is preferred that the concentration of these gases in this stream be kept to a minimum.
- The process of the invention can be used to produce gases from any solid underground carbonaceous formation. Among typical carbonaceous deposits from which valuable fuel gases can be produced are anthracite, bituminous and brown coal, lignite, peat.
- To prepare an underground formation for recovery of the desired gaseous substances by the process of the invention, provision is made for introducing strongly adsorbable fluid and weakly adsorbable gas into the formation and for withdrawing the desired gaseous substances therefrom. This can be conveniently accomplished by drilling one or more injection wells and one or more production wells into the formation. A single injection well and a single product well can be used, however it is usually more effective to provide an array of injection wells and production wells. For example, injection wells can be positioned at the corners of a rectangular section above the formation and a production well can be positioned in the centre of the rectangle. Alternatively, the gas production field can consist of a central injection well and several production wells arranged around the injection well or a line-drive pattern, i.e. alternating runs of injection wells and production wells. The arrangement of the gas recovery system is not critical and forms no part of the invention. For simplicity the invention will be described as it applies to the extraction of methane from a coal deposit using a single injection well, a single gas production well, liquefied carbon dioxide as the strongly adsorbably fluid and nitrogen as the weakly adsorbable gas. It is to be understood, however, that the invention is not limited to this system.
- The invention will now be described by way of example with reference to the accompanying drawings, in which; The invention is illustrated in the drawings, in which:
- Fig. 1 is a side elevation of a subterranean formation containing a solid carbonaceous deposit, wherein the deposit is penetrated by an injection well and a production well.
- Fig. 2 is a side elevation of the formation of Fig. 1, after liquefied gas has been injected into the deposit illustrated therein; and
- Fig. 3 is a side elevation of the formation shown in Fig. 1 after liquefied gas and weakly adsorbable gas have been injected into the deposit illustrated therein.
- In the drawings like characters designate like or corresponding parts throughout the several views. Auxiliary valves, lines and equipment not necessary for an understanding of the invention have been omitted from the drawings.
- Considering first Fig. 1, illustrated therein is a
coal deposit 2, which is penetrated by injection well 4 and gas production well 6. Line 8 carries the fluid to be injected into the coal deposit from a source (not shown) to pump 10, which raises the pressure of the fluid being injected into the coal deposit sufficiently to enable it to penetrate the deposit. The high pressure fluid is carried into well 4 vialine 12. The fluid in well 4 passes through the wall of well 4 throughopenings 14. Methane is withdrawn from the coal deposit bypump 16. The methane enters well 6 throughopenings 18, rises to the surface throughwell 4 and enters pump 16 vialine 20. The methane is discharged frompump 16 to storage or to a product purification unit (not shown) throughline 22. - Fig. 2 illustrates the first step of the process of the invention. During this step liquefied carbon dioxide is pumped into
coal deposit 2. The direction of movement of the liquefied carbon dioxide throughwell 4 is represented byarrow 24 and the direction of flow of the liquefied carbon dioxide into the coal deposit is represented byarrows 26. It appears that the liquefied carbon dioxide passing through the coal deposit forms a front, represented byreference numeral 28. As the liquefied carbon dioxide moves through the coal deposit it stimulates the release of methane from the deposit. It is not known with certainty how this is accomplished, but it is believed that this effect is perhaps caused by a combination of factors, such as fracturing of the coal deposit structure from the force of the liquefied gas in the pores of the coal and expansion of seams in the coal deposit. It appears likely that some of the liquefied carbon dioxide is vaporised as it passes through the warm formation and that some methane is desorbed from the coal by the vaporised carbon dioxide and some is desorbed by the liquefied carbon dioxide. In any event the methane is swept through the coal deposit by the carbon dioxide. In Fig. 2, the methane concentrates ahead offront 28, in the region represented byreference numeral 30. - The second step of the invention is illustrated in Fig. 3. In this step nitrogen is pumped into the coal deposit after the desired amount of liquefied carbon dioxide is pumped into the deposit. The flow of nitrogen through
well 4 is represented by arrow 32, and the flow of nitrogen intocoal deposit 2 is represented byarrows 34. It is postulted that as the nitrogen passes through the coal deposit it forms a front 36 behind the body of liquefied carbon dioxide, the latter of which is represented byreference numeral 38. The body of liquefied carbon dioxide appears to act as a buffer between the methane and the nitrogen, thereby tending the inhibit mixing of the nitrogen with the methane being recovered from the deposit. Again, the reason for this is not known, but it appears that a possible explanation for this effect is that frothing of the liquefied carbon dioxide may result at the liquefied carbon dioxide-nitrogen interface, and the froth may to some extent interfere with the passage of the nitrogen into the liquefied carbon dioxide. The flow of methane released from the deposit into production well 6 is represented byarrows 40, and the flow of the methane through well 6 is represented byarrow 42. - The invention is further exemplified by the following hypothetical examples, in which parts, percentages and ratios are on a weight basis, unless otherwise indicated.
- Injection and production wells are drilled into a coal seam containing adsorbed methane in a repeating line-drive pattern having a well-to-well distance of 1000 ft. Liquefied carbon dioxide is then injected into the coal seam through the injection wells, until a total of 15,000 bbl. per well is injected into the seam. Next, nitrogen is injected into the coal seam through the injection wells as a propellant gas. As the nitrogen is pumped into the wells, a methane-rich gas stream is removed from the seam through the production wells. When about 3.6 (106) standard cubic feet (scf) per well of nitrogen has been injected into the coal seam, the concentration of nitrogen in the product stream will begin to increase, indicating that break-through of the nitrogen propellant gas will have occurred. At this point the volume of methane removed from the coal seam will have reached about 42.9 (106) scf per well.
- The procedure of Example I is repeated except that no nitrogen propellant gas is injected into the coal seam. The total volume of methane removed from the coal seam will be about 23.7 (106) scf per well.
- The procedure of Example I is repeated except that no liquefied carbon dioxide is injected into the coal seam. At the point of nitrogen break-through, 3.0 (106) scf per well of nitrogen will have been injected into the coal seam and the volume of methane removed from the well will have reached about 15.9 (106) scf per well.
- Examination of the above examples shows that the volume of methane recovered from the coal seam is considerably greater when first liquefied carbon dioxide and then nitrogen are injected into the coal seam to force methane from the coal seam than when either liquefied carbon dioxide or nitrogen are used alone to force the methane from the coal seam
Claims (10)
- A process for recovering an adsorbed fuel gas from an underground deposit comprising:(a) injecting a first stream comprising one or more strongly adsorbable fluids into said deposit;(b) injecting a second stream comprising one or more weakly adsorbable gases into said deposit, thereby causing said strongly adsorbable fluids to flow through said deposit and desorb said fuel gas therefrom; and(c) with drawing said fuel gas from said deposit.
- A process according to Claim 1, wherein said deposit is a carbonaceous deposit.
- A process according to Claim 1 or Claim 2, wherein said carbonaceous deposit is selected from coal, lignite, peat and mixtures thereof.
- A process according to any one of Claims 1 to 3, wherein said fuel gas is natural gas.
- A process according to any one of the preceding claims, wherein said fuel gas is comprises methane.
- A process according to any one of the preceding claims, wherein said first stream comprises carbon dioxide.
- A process according to claim 6, in which said carbon dioxide is introduced into said deposit in liquid state.
- A process according to Claim 6, wherein said first stream additionally includes nitrogen.
- A process according to any one of the preceding claims, wherein said second stream comprises one or more gases selected from nitrogen, helium, argon, air and mixtures of these.
- A process according to claim 7, in which the deposit is penetrated by an injection well and a production well, the first stream and the second stream are introduced into the deposit through the injection well and the second stream is withdrawn through the production well.
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US88350492A | 1992-05-15 | 1992-05-15 | |
US883504 | 1992-05-15 | ||
US07/986,842 US5332036A (en) | 1992-05-15 | 1992-12-04 | Method of recovery of natural gases from underground coal formations |
US986842 | 1992-12-04 |
Publications (2)
Publication Number | Publication Date |
---|---|
EP0570228A1 EP0570228A1 (en) | 1993-11-18 |
EP0570228B1 true EP0570228B1 (en) | 1996-09-25 |
Family
ID=27128692
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP93303723A Expired - Lifetime EP0570228B1 (en) | 1992-05-15 | 1993-05-13 | Recovery of fuel gases from underground deposits |
Country Status (6)
Country | Link |
---|---|
US (1) | US5332036A (en) |
EP (1) | EP0570228B1 (en) |
AU (1) | AU669517B2 (en) |
CA (1) | CA2094449C (en) |
DE (1) | DE69304992T2 (en) |
ZA (1) | ZA932886B (en) |
Cited By (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US6581684B2 (en) | 2000-04-24 | 2003-06-24 | Shell Oil Company | In Situ thermal processing of a hydrocarbon containing formation to produce sulfur containing formation fluids |
US6588504B2 (en) | 2000-04-24 | 2003-07-08 | Shell Oil Company | In situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids |
US6698515B2 (en) | 2000-04-24 | 2004-03-02 | Shell Oil Company | In situ thermal processing of a coal formation using a relatively slow heating rate |
US6715548B2 (en) | 2000-04-24 | 2004-04-06 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to produce nitrogen containing formation fluids |
US6715546B2 (en) | 2000-04-24 | 2004-04-06 | Shell Oil Company | In situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore |
US6782947B2 (en) | 2001-04-24 | 2004-08-31 | Shell Oil Company | In situ thermal processing of a relatively impermeable formation to increase permeability of the formation |
US7735935B2 (en) | 2001-04-24 | 2010-06-15 | Shell Oil Company | In situ thermal processing of an oil shale formation containing carbonate minerals |
US7942203B2 (en) | 2003-04-24 | 2011-05-17 | Shell Oil Company | Thermal processes for subsurface formations |
US8224163B2 (en) | 2002-10-24 | 2012-07-17 | Shell Oil Company | Variable frequency temperature limited heaters |
Families Citing this family (111)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5439054A (en) * | 1994-04-01 | 1995-08-08 | Amoco Corporation | Method for treating a mixture of gaseous fluids within a solid carbonaceous subterranean formation |
PL176443B1 (en) * | 1994-04-01 | 1999-05-31 | Amoco Corp | Method of distributing carbon dioxide within a coal bed with simultaneous methane recovery therefrom |
US5501273A (en) * | 1994-10-04 | 1996-03-26 | Amoco Corporation | Method for determining the reservoir properties of a solid carbonaceous subterranean formation |
US5944104A (en) * | 1996-01-31 | 1999-08-31 | Vastar Resources, Inc. | Chemically induced stimulation of subterranean carbonaceous formations with gaseous oxidants |
US5865248A (en) * | 1996-01-31 | 1999-02-02 | Vastar Resources, Inc. | Chemically induced permeability enhancement of subterranean coal formation |
US5964290A (en) * | 1996-01-31 | 1999-10-12 | Vastar Resources, Inc. | Chemically induced stimulation of cleat formation in a subterranean coal formation |
US5967233A (en) * | 1996-01-31 | 1999-10-19 | Vastar Resources, Inc. | Chemically induced stimulation of subterranean carbonaceous formations with aqueous oxidizing solutions |
US5669444A (en) * | 1996-01-31 | 1997-09-23 | Vastar Resources, Inc. | Chemically induced stimulation of coal cleat formation |
US5769165A (en) * | 1996-01-31 | 1998-06-23 | Vastar Resources Inc. | Method for increasing methane recovery from a subterranean coal formation by injection of tail gas from a hydrocarbon synthesis process |
US6412559B1 (en) | 2000-11-24 | 2002-07-02 | Alberta Research Council Inc. | Process for recovering methane and/or sequestering fluids |
WO2003036039A1 (en) | 2001-10-24 | 2003-05-01 | Shell Internationale Research Maatschappij B.V. | In situ production of a blending agent from a hydrocarbon containing formation |
EP1738052B1 (en) | 2004-04-23 | 2008-04-16 | Shell International Research Maatschappij B.V. | Inhibiting reflux in a heated well of an in situ conversion system |
US7575052B2 (en) | 2005-04-22 | 2009-08-18 | Shell Oil Company | In situ conversion process utilizing a closed loop heating system |
JP5570723B2 (en) | 2005-10-24 | 2014-08-13 | シエル・インターナシヨネイル・リサーチ・マーチヤツピイ・ベー・ウイ | Method for producing additional crude product by cracking crude product |
WO2007149622A2 (en) | 2006-04-21 | 2007-12-27 | Shell Oil Company | Sulfur barrier for use with in situ processes for treating formations |
US7431084B1 (en) | 2006-09-11 | 2008-10-07 | The Regents Of The University Of California | Production of hydrogen from underground coal gasification |
RU2451170C2 (en) | 2006-10-20 | 2012-05-20 | Шелл Интернэшнл Рисерч Маатсхаппий Б.В. | Process of incremental heating of hydrocarbon containing formation in chess-board order |
US8327681B2 (en) | 2007-04-20 | 2012-12-11 | Shell Oil Company | Wellbore manufacturing processes for in situ heat treatment processes |
AU2008312713B2 (en) | 2007-10-19 | 2012-06-14 | Shell Internationale Research Maatschappij B.V. | Systems, methods, and processes utilized for treating subsurface formations |
CN101190743B (en) * | 2007-11-30 | 2013-11-06 | 中国科学院武汉岩土力学研究所 | Carbon dioxide geological sequestration method based on mixed fluid self-detaching |
CN101981162B (en) | 2008-03-28 | 2014-07-02 | 埃克森美孚上游研究公司 | Low emission power generation and hydrocarbon recovery systems and methods |
WO2009120779A2 (en) | 2008-03-28 | 2009-10-01 | Exxonmobil Upstream Research Company | Low emission power generation and hydrocarbon recovery systems and methods |
CN102007266B (en) | 2008-04-18 | 2014-09-10 | 国际壳牌研究有限公司 | Using mines and tunnels for treating subsurface hydrocarbon containing formations system and method |
CA2739086A1 (en) | 2008-10-13 | 2010-04-22 | Shell Internationale Research Maatschappij B.V. | Using self-regulating nuclear reactors in treating a subsurface formation |
PL2344738T3 (en) | 2008-10-14 | 2019-09-30 | Exxonmobil Upstream Research Company | Method and system for controlling the products of combustion |
WO2010107777A1 (en) * | 2009-03-19 | 2010-09-23 | Kreis Syngas, Llc | Integrated production and utilization of synthesis gas |
US8851170B2 (en) | 2009-04-10 | 2014-10-07 | Shell Oil Company | Heater assisted fluid treatment of a subsurface formation |
SG10201402156TA (en) | 2009-06-05 | 2014-10-30 | Exxonmobil Upstream Res Co | Combustor systems and methods for using same |
WO2011002556A1 (en) | 2009-07-01 | 2011-01-06 | Exxonmobil Upstream Research Company | System and method for producing coal bed methane |
MX341477B (en) | 2009-11-12 | 2016-08-22 | Exxonmobil Upstream Res Company * | Low emission power generation and hydrocarbon recovery systems and methods. |
US8739874B2 (en) | 2010-04-09 | 2014-06-03 | Shell Oil Company | Methods for heating with slots in hydrocarbon formations |
US8833453B2 (en) | 2010-04-09 | 2014-09-16 | Shell Oil Company | Electrodes for electrical current flow heating of subsurface formations with tapered copper thickness |
US8631866B2 (en) | 2010-04-09 | 2014-01-21 | Shell Oil Company | Leak detection in circulated fluid systems for heating subsurface formations |
US9033042B2 (en) | 2010-04-09 | 2015-05-19 | Shell Oil Company | Forming bitumen barriers in subsurface hydrocarbon formations |
EA029523B1 (en) | 2010-07-02 | 2018-04-30 | Эксонмобил Апстрим Рисерч Компани | Integrated system for power generation and lowering coemissions |
TWI593878B (en) | 2010-07-02 | 2017-08-01 | 艾克頌美孚上游研究公司 | Systems and methods for controlling combustion of a fuel |
BR112012031505A2 (en) | 2010-07-02 | 2016-11-01 | Exxonmobil Upstream Res Co | stoichiometric combustion of enriched air with exhaust gas recirculation |
AU2011271634B2 (en) | 2010-07-02 | 2016-01-28 | Exxonmobil Upstream Research Company | Stoichiometric combustion with exhaust gas recirculation and direct contact cooler |
SG186084A1 (en) | 2010-07-02 | 2013-01-30 | Exxonmobil Upstream Res Co | Low emission triple-cycle power generation systems and methods |
WO2012018457A1 (en) | 2010-08-06 | 2012-02-09 | Exxonmobil Upstream Research Company | Systems and methods for optimizing stoichiometric combustion |
WO2012018458A1 (en) | 2010-08-06 | 2012-02-09 | Exxonmobil Upstream Research Company | System and method for exhaust gas extraction |
EP2469018A1 (en) * | 2010-12-21 | 2012-06-27 | Linde AG | Method for the methane recovery from coal |
TWI563166B (en) | 2011-03-22 | 2016-12-21 | Exxonmobil Upstream Res Co | Integrated generation systems and methods for generating power |
TWI564474B (en) | 2011-03-22 | 2017-01-01 | 艾克頌美孚上游研究公司 | Integrated systems for controlling stoichiometric combustion in turbine systems and methods of generating power using the same |
TWI563165B (en) | 2011-03-22 | 2016-12-21 | Exxonmobil Upstream Res Co | Power generation system and method for generating power |
TWI593872B (en) | 2011-03-22 | 2017-08-01 | 艾克頌美孚上游研究公司 | Integrated system and methods of generating power |
US9016370B2 (en) | 2011-04-08 | 2015-04-28 | Shell Oil Company | Partial solution mining of hydrocarbon containing layers prior to in situ heat treatment |
CA2850741A1 (en) | 2011-10-07 | 2013-04-11 | Manuel Alberto GONZALEZ | Thermal expansion accommodation for circulated fluid systems used to heat subsurface formations |
WO2013095829A2 (en) * | 2011-12-20 | 2013-06-27 | Exxonmobil Upstream Research Company | Enhanced coal-bed methane production |
US9605524B2 (en) | 2012-01-23 | 2017-03-28 | Genie Ip B.V. | Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation |
CN104428489A (en) | 2012-01-23 | 2015-03-18 | 吉尼Ip公司 | Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation |
US9353682B2 (en) | 2012-04-12 | 2016-05-31 | General Electric Company | Methods, systems and apparatus relating to combustion turbine power plants with exhaust gas recirculation |
US10273880B2 (en) | 2012-04-26 | 2019-04-30 | General Electric Company | System and method of recirculating exhaust gas for use in a plurality of flow paths in a gas turbine engine |
US9784185B2 (en) | 2012-04-26 | 2017-10-10 | General Electric Company | System and method for cooling a gas turbine with an exhaust gas provided by the gas turbine |
US9599070B2 (en) | 2012-11-02 | 2017-03-21 | General Electric Company | System and method for oxidant compression in a stoichiometric exhaust gas recirculation gas turbine system |
US10161312B2 (en) | 2012-11-02 | 2018-12-25 | General Electric Company | System and method for diffusion combustion with fuel-diluent mixing in a stoichiometric exhaust gas recirculation gas turbine system |
US9631815B2 (en) | 2012-12-28 | 2017-04-25 | General Electric Company | System and method for a turbine combustor |
US10107495B2 (en) | 2012-11-02 | 2018-10-23 | General Electric Company | Gas turbine combustor control system for stoichiometric combustion in the presence of a diluent |
US9708977B2 (en) | 2012-12-28 | 2017-07-18 | General Electric Company | System and method for reheat in gas turbine with exhaust gas recirculation |
US9611756B2 (en) | 2012-11-02 | 2017-04-04 | General Electric Company | System and method for protecting components in a gas turbine engine with exhaust gas recirculation |
US9574496B2 (en) | 2012-12-28 | 2017-02-21 | General Electric Company | System and method for a turbine combustor |
US10215412B2 (en) | 2012-11-02 | 2019-02-26 | General Electric Company | System and method for load control with diffusion combustion in a stoichiometric exhaust gas recirculation gas turbine system |
US9803865B2 (en) | 2012-12-28 | 2017-10-31 | General Electric Company | System and method for a turbine combustor |
US9869279B2 (en) | 2012-11-02 | 2018-01-16 | General Electric Company | System and method for a multi-wall turbine combustor |
US10208677B2 (en) | 2012-12-31 | 2019-02-19 | General Electric Company | Gas turbine load control system |
US9581081B2 (en) | 2013-01-13 | 2017-02-28 | General Electric Company | System and method for protecting components in a gas turbine engine with exhaust gas recirculation |
US9512759B2 (en) | 2013-02-06 | 2016-12-06 | General Electric Company | System and method for catalyst heat utilization for gas turbine with exhaust gas recirculation |
TW201502356A (en) | 2013-02-21 | 2015-01-16 | Exxonmobil Upstream Res Co | Reducing oxygen in a gas turbine exhaust |
US9938861B2 (en) | 2013-02-21 | 2018-04-10 | Exxonmobil Upstream Research Company | Fuel combusting method |
US10221762B2 (en) | 2013-02-28 | 2019-03-05 | General Electric Company | System and method for a turbine combustor |
US9618261B2 (en) | 2013-03-08 | 2017-04-11 | Exxonmobil Upstream Research Company | Power generation and LNG production |
TW201500635A (en) | 2013-03-08 | 2015-01-01 | Exxonmobil Upstream Res Co | Processing exhaust for use in enhanced oil recovery |
US20140250945A1 (en) | 2013-03-08 | 2014-09-11 | Richard A. Huntington | Carbon Dioxide Recovery |
CN105008499A (en) | 2013-03-08 | 2015-10-28 | 埃克森美孚上游研究公司 | Power generation and methane recovery from methane hydrates |
US9855385B2 (en) * | 2013-03-13 | 2018-01-02 | Bayer Healthcare Llc | Multiple compartment syringe |
CN104234737A (en) * | 2013-06-21 | 2014-12-24 | 肖栋 | Enzymolysis-boosted coal-seam methane desorption technique and method |
US9631542B2 (en) | 2013-06-28 | 2017-04-25 | General Electric Company | System and method for exhausting combustion gases from gas turbine engines |
TWI654368B (en) | 2013-06-28 | 2019-03-21 | 美商艾克頌美孚上游研究公司 | System, method and media for controlling exhaust gas flow in an exhaust gas recirculation gas turbine system |
US9617914B2 (en) | 2013-06-28 | 2017-04-11 | General Electric Company | Systems and methods for monitoring gas turbine systems having exhaust gas recirculation |
US9835089B2 (en) | 2013-06-28 | 2017-12-05 | General Electric Company | System and method for a fuel nozzle |
US9587510B2 (en) | 2013-07-30 | 2017-03-07 | General Electric Company | System and method for a gas turbine engine sensor |
US9903588B2 (en) | 2013-07-30 | 2018-02-27 | General Electric Company | System and method for barrier in passage of combustor of gas turbine engine with exhaust gas recirculation |
US9951658B2 (en) | 2013-07-31 | 2018-04-24 | General Electric Company | System and method for an oxidant heating system |
US9752458B2 (en) | 2013-12-04 | 2017-09-05 | General Electric Company | System and method for a gas turbine engine |
US10030588B2 (en) | 2013-12-04 | 2018-07-24 | General Electric Company | Gas turbine combustor diagnostic system and method |
US10227920B2 (en) | 2014-01-15 | 2019-03-12 | General Electric Company | Gas turbine oxidant separation system |
US9915200B2 (en) | 2014-01-21 | 2018-03-13 | General Electric Company | System and method for controlling the combustion process in a gas turbine operating with exhaust gas recirculation |
US9863267B2 (en) | 2014-01-21 | 2018-01-09 | General Electric Company | System and method of control for a gas turbine engine |
US10079564B2 (en) | 2014-01-27 | 2018-09-18 | General Electric Company | System and method for a stoichiometric exhaust gas recirculation gas turbine system |
US10047633B2 (en) | 2014-05-16 | 2018-08-14 | General Electric Company | Bearing housing |
US9885290B2 (en) | 2014-06-30 | 2018-02-06 | General Electric Company | Erosion suppression system and method in an exhaust gas recirculation gas turbine system |
US10655542B2 (en) | 2014-06-30 | 2020-05-19 | General Electric Company | Method and system for startup of gas turbine system drive trains with exhaust gas recirculation |
US10060359B2 (en) | 2014-06-30 | 2018-08-28 | General Electric Company | Method and system for combustion control for gas turbine system with exhaust gas recirculation |
CN105317411A (en) * | 2014-08-03 | 2016-02-10 | 山东拓普石油装备有限公司 | High-pressure, oxygen-free, yield-increasing and plug-release gas injection device of CBM (Coal Bed Methane) well and using method of high-pressure, oxygen-free, yield-increasing and plug-release gas injection device |
US9819292B2 (en) | 2014-12-31 | 2017-11-14 | General Electric Company | Systems and methods to respond to grid overfrequency events for a stoichiometric exhaust recirculation gas turbine |
US9869247B2 (en) | 2014-12-31 | 2018-01-16 | General Electric Company | Systems and methods of estimating a combustion equivalence ratio in a gas turbine with exhaust gas recirculation |
US10788212B2 (en) | 2015-01-12 | 2020-09-29 | General Electric Company | System and method for an oxidant passageway in a gas turbine system with exhaust gas recirculation |
US10094566B2 (en) | 2015-02-04 | 2018-10-09 | General Electric Company | Systems and methods for high volumetric oxidant flow in gas turbine engine with exhaust gas recirculation |
US10316746B2 (en) | 2015-02-04 | 2019-06-11 | General Electric Company | Turbine system with exhaust gas recirculation, separation and extraction |
US10253690B2 (en) | 2015-02-04 | 2019-04-09 | General Electric Company | Turbine system with exhaust gas recirculation, separation and extraction |
US10267270B2 (en) | 2015-02-06 | 2019-04-23 | General Electric Company | Systems and methods for carbon black production with a gas turbine engine having exhaust gas recirculation |
US10145269B2 (en) | 2015-03-04 | 2018-12-04 | General Electric Company | System and method for cooling discharge flow |
US10480792B2 (en) | 2015-03-06 | 2019-11-19 | General Electric Company | Fuel staging in a gas turbine engine |
CA2956439C (en) | 2015-10-08 | 2017-11-14 | 1304338 Alberta Ltd. | Method of producing heavy oil using a fuel cell |
CA2914070C (en) | 2015-12-07 | 2023-08-01 | 1304338 Alberta Ltd. | Upgrading oil using supercritical fluids |
CN106285571B (en) * | 2016-09-29 | 2018-11-30 | 江苏省水利科学研究院 | A kind of pre- mining system of water resources in coal mines subregion and method |
WO2018170830A1 (en) * | 2017-03-23 | 2018-09-27 | 陈信平 | Method for increasing production of coal bed gas by injecting high temperature air |
CA2997634A1 (en) | 2018-03-07 | 2019-09-07 | 1304342 Alberta Ltd. | Production of petrochemical feedstocks and products using a fuel cell |
CN110714742B (en) * | 2018-07-12 | 2021-11-09 | 中国石油化工股份有限公司 | Method for improving recovery ratio of bottom water condensate gas reservoir |
CN112647906B (en) * | 2020-12-18 | 2021-12-21 | 华能煤炭技术研究有限公司 | Method for extracting gas from ground of multi-goaf without coal pillar |
CN112796729B (en) * | 2020-12-24 | 2023-03-21 | 克拉玛依科美利化工有限责任公司 | Quasi-dry method liquid supercritical CO 2 Acid fracturing method |
Family Cites Families (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4043395A (en) * | 1975-03-13 | 1977-08-23 | Continental Oil Company | Method for removing methane from coal |
US4883122A (en) * | 1988-09-27 | 1989-11-28 | Amoco Corporation | Method of coalbed methane production |
US5074357A (en) * | 1989-12-27 | 1991-12-24 | Marathon Oil Company | Process for in-situ enrichment of gas used in miscible flooding |
US5099921A (en) * | 1991-02-11 | 1992-03-31 | Amoco Corporation | Recovery of methane from solid carbonaceous subterranean formations |
US5085274A (en) * | 1991-02-11 | 1992-02-04 | Amoco Corporation | Recovery of methane from solid carbonaceous subterranean of formations |
US5147111A (en) * | 1991-08-02 | 1992-09-15 | Atlantic Richfield Company | Cavity induced stimulation method of coal degasification wells |
-
1992
- 1992-12-04 US US07/986,842 patent/US5332036A/en not_active Expired - Lifetime
-
1993
- 1993-04-20 CA CA002094449A patent/CA2094449C/en not_active Expired - Fee Related
- 1993-04-23 ZA ZA932886A patent/ZA932886B/en unknown
- 1993-05-10 AU AU38496/93A patent/AU669517B2/en not_active Ceased
- 1993-05-13 DE DE69304992T patent/DE69304992T2/en not_active Expired - Fee Related
- 1993-05-13 EP EP93303723A patent/EP0570228B1/en not_active Expired - Lifetime
Cited By (58)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US6581684B2 (en) | 2000-04-24 | 2003-06-24 | Shell Oil Company | In Situ thermal processing of a hydrocarbon containing formation to produce sulfur containing formation fluids |
US6588504B2 (en) | 2000-04-24 | 2003-07-08 | Shell Oil Company | In situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids |
US6591907B2 (en) | 2000-04-24 | 2003-07-15 | Shell Oil Company | In situ thermal processing of a coal formation with a selected vitrinite reflectance |
US6591906B2 (en) | 2000-04-24 | 2003-07-15 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation with a selected oxygen content |
US6607033B2 (en) | 2000-04-24 | 2003-08-19 | Shell Oil Company | In Situ thermal processing of a coal formation to produce a condensate |
US6609570B2 (en) | 2000-04-24 | 2003-08-26 | Shell Oil Company | In situ thermal processing of a coal formation and ammonia production |
US6688387B1 (en) | 2000-04-24 | 2004-02-10 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to produce a hydrocarbon condensate |
US6698515B2 (en) | 2000-04-24 | 2004-03-02 | Shell Oil Company | In situ thermal processing of a coal formation using a relatively slow heating rate |
US6702016B2 (en) | 2000-04-24 | 2004-03-09 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation with heat sources located at an edge of a formation layer |
US6708758B2 (en) | 2000-04-24 | 2004-03-23 | Shell Oil Company | In situ thermal processing of a coal formation leaving one or more selected unprocessed areas |
US6712137B2 (en) | 2000-04-24 | 2004-03-30 | Shell Oil Company | In situ thermal processing of a coal formation to pyrolyze a selected percentage of hydrocarbon material |
US6712135B2 (en) | 2000-04-24 | 2004-03-30 | Shell Oil Company | In situ thermal processing of a coal formation in reducing environment |
US6712136B2 (en) | 2000-04-24 | 2004-03-30 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation using a selected production well spacing |
US6715549B2 (en) | 2000-04-24 | 2004-04-06 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation with a selected atomic oxygen to carbon ratio |
US6715547B2 (en) | 2000-04-24 | 2004-04-06 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to form a substantially uniform, high permeability formation |
US6715548B2 (en) | 2000-04-24 | 2004-04-06 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to produce nitrogen containing formation fluids |
US6715546B2 (en) | 2000-04-24 | 2004-04-06 | Shell Oil Company | In situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore |
US6719047B2 (en) | 2000-04-24 | 2004-04-13 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation in a hydrogen-rich environment |
US6722430B2 (en) | 2000-04-24 | 2004-04-20 | Shell Oil Company | In situ thermal processing of a coal formation with a selected oxygen content and/or selected O/C ratio |
US6722431B2 (en) | 2000-04-24 | 2004-04-20 | Shell Oil Company | In situ thermal processing of hydrocarbons within a relatively permeable formation |
US6722429B2 (en) | 2000-04-24 | 2004-04-20 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation leaving one or more selected unprocessed areas |
US6725928B2 (en) | 2000-04-24 | 2004-04-27 | Shell Oil Company | In situ thermal processing of a coal formation using a distributed combustor |
US6725920B2 (en) | 2000-04-24 | 2004-04-27 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to convert a selected amount of total organic carbon into hydrocarbon products |
US6725921B2 (en) | 2000-04-24 | 2004-04-27 | Shell Oil Company | In situ thermal processing of a coal formation by controlling a pressure of the formation |
US6729396B2 (en) | 2000-04-24 | 2004-05-04 | Shell Oil Company | In situ thermal processing of a coal formation to produce hydrocarbons having a selected carbon number range |
US6729395B2 (en) | 2000-04-24 | 2004-05-04 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation with a selected ratio of heat sources to production wells |
US6729401B2 (en) | 2000-04-24 | 2004-05-04 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation and ammonia production |
US6729397B2 (en) | 2000-04-24 | 2004-05-04 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation with a selected vitrinite reflectance |
US6732795B2 (en) | 2000-04-24 | 2004-05-11 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to pyrolyze a selected percentage of hydrocarbon material |
US6732794B2 (en) | 2000-04-24 | 2004-05-11 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to produce a mixture with a selected hydrogen content |
US6732796B2 (en) | 2000-04-24 | 2004-05-11 | Shell Oil Company | In situ production of synthesis gas from a hydrocarbon containing formation, the synthesis gas having a selected H2 to CO ratio |
US6736215B2 (en) | 2000-04-24 | 2004-05-18 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation, in situ production of synthesis gas, and carbon dioxide sequestration |
US6739393B2 (en) | 2000-04-24 | 2004-05-25 | Shell Oil Company | In situ thermal processing of a coal formation and tuning production |
US6739394B2 (en) | 2000-04-24 | 2004-05-25 | Shell Oil Company | Production of synthesis gas from a hydrocarbon containing formation |
US6742588B2 (en) | 2000-04-24 | 2004-06-01 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to produce formation fluids having a relatively low olefin content |
US6742587B2 (en) | 2000-04-24 | 2004-06-01 | Shell Oil Company | In situ thermal processing of a coal formation to form a substantially uniform, relatively high permeable formation |
US6742593B2 (en) | 2000-04-24 | 2004-06-01 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation using heat transfer from a heat transfer fluid to heat the formation |
US6742589B2 (en) | 2000-04-24 | 2004-06-01 | Shell Oil Company | In situ thermal processing of a coal formation using repeating triangular patterns of heat sources |
US6745832B2 (en) | 2000-04-24 | 2004-06-08 | Shell Oil Company | Situ thermal processing of a hydrocarbon containing formation to control product composition |
US6745837B2 (en) | 2000-04-24 | 2004-06-08 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation using a controlled heating rate |
US6745831B2 (en) | 2000-04-24 | 2004-06-08 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation by controlling a pressure of the formation |
US6749021B2 (en) | 2000-04-24 | 2004-06-15 | Shell Oil Company | In situ thermal processing of a coal formation using a controlled heating rate |
US6752210B2 (en) | 2000-04-24 | 2004-06-22 | Shell Oil Company | In situ thermal processing of a coal formation using heat sources positioned within open wellbores |
US6758268B2 (en) | 2000-04-24 | 2004-07-06 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation using a relatively slow heating rate |
US6761216B2 (en) | 2000-04-24 | 2004-07-13 | Shell Oil Company | In situ thermal processing of a coal formation to produce hydrocarbon fluids and synthesis gas |
US6763886B2 (en) | 2000-04-24 | 2004-07-20 | Shell Oil Company | In situ thermal processing of a coal formation with carbon dioxide sequestration |
US6769485B2 (en) | 2000-04-24 | 2004-08-03 | Shell Oil Company | In situ production of synthesis gas from a coal formation through a heat source wellbore |
US6769483B2 (en) | 2000-04-24 | 2004-08-03 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation using conductor in conduit heat sources |
US6789625B2 (en) | 2000-04-24 | 2004-09-14 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation using exposed metal heat sources |
US6805195B2 (en) | 2000-04-24 | 2004-10-19 | Shell Oil Company | In situ thermal processing of a hydrocarbon containing formation to produce hydrocarbon fluids and synthesis gas |
US6820688B2 (en) | 2000-04-24 | 2004-11-23 | Shell Oil Company | In situ thermal processing of coal formation with a selected hydrogen content and/or selected H/C ratio |
US6782947B2 (en) | 2001-04-24 | 2004-08-31 | Shell Oil Company | In situ thermal processing of a relatively impermeable formation to increase permeability of the formation |
US7735935B2 (en) | 2001-04-24 | 2010-06-15 | Shell Oil Company | In situ thermal processing of an oil shale formation containing carbonate minerals |
US8224163B2 (en) | 2002-10-24 | 2012-07-17 | Shell Oil Company | Variable frequency temperature limited heaters |
US8224164B2 (en) | 2002-10-24 | 2012-07-17 | Shell Oil Company | Insulated conductor temperature limited heaters |
US8238730B2 (en) | 2002-10-24 | 2012-08-07 | Shell Oil Company | High voltage temperature limited heaters |
US7942203B2 (en) | 2003-04-24 | 2011-05-17 | Shell Oil Company | Thermal processes for subsurface formations |
US8579031B2 (en) | 2003-04-24 | 2013-11-12 | Shell Oil Company | Thermal processes for subsurface formations |
Also Published As
Publication number | Publication date |
---|---|
DE69304992T2 (en) | 1997-02-06 |
AU3849693A (en) | 1993-11-18 |
DE69304992D1 (en) | 1996-10-31 |
ZA932886B (en) | 1994-10-13 |
CA2094449C (en) | 1996-08-13 |
US5332036A (en) | 1994-07-26 |
EP0570228A1 (en) | 1993-11-18 |
CA2094449A1 (en) | 1993-11-16 |
AU669517B2 (en) | 1996-06-13 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
EP0570228B1 (en) | Recovery of fuel gases from underground deposits | |
US5566756A (en) | Method for recovering methane from a solid carbonaceous subterranean formation | |
US5388640A (en) | Method for producing methane-containing gaseous mixtures | |
US5388641A (en) | Method for reducing the inert gas fraction in methane-containing gaseous mixtures obtained from underground formations | |
US5074357A (en) | Process for in-situ enrichment of gas used in miscible flooding | |
AU694458B2 (en) | Method for the recovery of coal bed methane | |
US5388643A (en) | Coalbed methane recovery using pressure swing adsorption separation | |
US4043395A (en) | Method for removing methane from coal | |
US4099568A (en) | Method for recovering viscous petroleum | |
US8622129B2 (en) | Method of injecting carbon dioxide | |
US5099921A (en) | Recovery of methane from solid carbonaceous subterranean formations | |
US3878892A (en) | Vertical downward gas-driven miscible blanket flooding oil recovery process | |
US7152675B2 (en) | Subterranean hydrogen storage process | |
US3065790A (en) | Oil recovery process | |
US7128150B2 (en) | Acid gas disposal method | |
US4391327A (en) | Solvent foam stimulation of coal degasification well | |
WO2011093945A1 (en) | Temporary field storage of gas to optimize field development | |
US3850245A (en) | Miscible displacement of petroleum | |
Holm | Status of CO2 and hydrocarbon miscible oil recovery methods | |
US3995693A (en) | Reservoir treatment by injecting mixture of CO2 and hydrocarbon gas | |
US4744417A (en) | Method for effectively handling CO2 -hydrocarbon gas mixture in a miscible CO2 flood for oil recovery | |
US4224992A (en) | Method for enhanced oil recovery | |
CA2176588C (en) | Method for disposing carbon dioxide in a coalbed and simultaneously recovering methane from the coalbed | |
US4187910A (en) | CO2 removal from hydrocarbon gas in water bearing underground reservoir | |
US3586107A (en) | Carbon dioxide slug drive |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
PUAI | Public reference made under article 153(3) epc to a published international application that has entered the european phase |
Free format text: ORIGINAL CODE: 0009012 |
|
AK | Designated contracting states |
Kind code of ref document: A1 Designated state(s): BE DE FR GB IT NL SE |
|
17P | Request for examination filed |
Effective date: 19940516 |
|
17Q | First examination report despatched |
Effective date: 19951109 |
|
GRAH | Despatch of communication of intention to grant a patent |
Free format text: ORIGINAL CODE: EPIDOS IGRA |
|
GRAH | Despatch of communication of intention to grant a patent |
Free format text: ORIGINAL CODE: EPIDOS IGRA |
|
GRAA | (expected) grant |
Free format text: ORIGINAL CODE: 0009210 |
|
AK | Designated contracting states |
Kind code of ref document: B1 Designated state(s): BE DE FR GB IT NL SE |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: NL Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 19960925 Ref country code: IT Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT;WARNING: LAPSES OF ITALIAN PATENTS WITH EFFECTIVE DATE BEFORE 2007 MAY HAVE OCCURRED AT ANY TIME BEFORE 2007. THE CORRECT EFFECTIVE DATE MAY BE DIFFERENT FROM THE ONE RECORDED. Effective date: 19960925 Ref country code: FR Effective date: 19960925 Ref country code: BE Effective date: 19960925 |
|
REF | Corresponds to: |
Ref document number: 69304992 Country of ref document: DE Date of ref document: 19961031 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: SE Effective date: 19961225 |
|
EN | Fr: translation not filed | ||
NLV1 | Nl: lapsed or annulled due to failure to fulfill the requirements of art. 29p and 29m of the patents act | ||
PLBE | No opposition filed within time limit |
Free format text: ORIGINAL CODE: 0009261 |
|
STAA | Information on the status of an ep patent application or granted ep patent |
Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT |
|
26N | No opposition filed | ||
REG | Reference to a national code |
Ref country code: GB Ref legal event code: IF02 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: DE Payment date: 20080630 Year of fee payment: 16 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: GB Payment date: 20080529 Year of fee payment: 16 |
|
GBPC | Gb: european patent ceased through non-payment of renewal fee |
Effective date: 20090513 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: GB Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20090513 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: DE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20091201 |